Page 1521 – RTO Insider

October 13, 2015

Company Briefs

The powerhouse at Duke Energy’s retired Cliffside Steam Station in Mooresboro, N.C., came down in a cloud of dust last week, the latest demolition Duke has conducted to modernize its generation fleet.

The coal-fired station went into service in 1940, and units 1 through 4 were retired in 2011. Units 5 and 6 are coal-fired units equipped with modern scrubber technology and still operate as part of the James E. Rogers Energy Complex.

See a video of the powerhouse implosion here.

More: Duke Energy

Entergy Execs Announce 2016 Exits

Entergy Executive Vice President and Chief Operating Officer Mark Savoff and Executive Vice President and Chief Nuclear Officer Jeff Forbes announced coordinated retirement dates last week.

Both executives plan to shift to advisory roles on Nov. 1 before retiring in 2016’s first quarter. At that time, Tim Mitchell, Entergy’s senior vice president of nuclear operations, will be named acting chief nuclear officer. In an executive restructure, the chief nuclear officer will directly report to Entergy Chairman and CEO Leo Denault. Mitchell will also be a candidate in Entergy’s search for a permanent chief nuclear officer.

Savoff and Forbes joined Entergy in 2003 and oversaw the transition of Entergy’s transmission system to MISO in 2013.

More: Entergy

DTE, GE Working on New Economic BWR Design

DTE Energy is teaming up with GE Hitachi to design a new type of boiling water reactor. While others are working on smaller, modular designs, the two companies are working on advancing the first-ever Economic Simplified Boiling Water Reactor (ESBWR).

The ESBWR incorporates passive safety systems, including a reactor that can cool itself for more than seven days without backup power or any human input. DTE has already received licensing from the Nuclear Regulatory Commission for the ESBWR.

The company said it has no current plans to start construction but said it is “keeping the option open, given the long-term environmental and economic advantages of nuclear power.” Dominion Virginia Power has selected the new design for a possible third reactor at its North Anna site in Virginia.

More: Nuclear Street

Alliant Eyes Boosting Solar Capacity by 50%

Alliant Energy subsidiary Interstate Power & Light in Iowa is planning to increase its total solar energy capacity by 50%, according to a recent request for proposals.

The company said it is looking to develop solar projects of between 1 and 10 MW. It currently purchases about 22 MW of solar capacity from about 1,650 customers in its service territory.

Alliant said the plan is unrelated to an Environmental Protection Agency air emissions settlement that calls for it to spend $6 million on environmental mitigation projects, which could include solar generation.

More: DesMoines Register

Xcel Energy to Accelerate Minnesota Wind, Solar Investments

Xcel Energy says it will reduce its greenhouse gas emissions in Minnesota by increasing wind and solar power investment and replacing two coal-burning generators with a natural gas-fired unit in the mid-2020s.

The plan, submitted to state regulators, would reduce carbon dioxide emissions in the Upper Midwest 60% by 2030 compared with 2005 levels. Until now, Xcel had aimed for a 40% reduction over that period.

Two of the three coal-fired units at Xcel’s Sherco power plant — Xcel’s largest in the region — would be retired in 2023 and 2026 under the plan. The two units, built in the 1970s, would be replaced by a new power plant fueled by natural gas.

More: Minneapolis Star Tribune

PSEG Combined-Cycle Project to Deliver Power by Summer 2018

Construction on PSEG Power’s 540-MW Sewaren 7 combined-cycle project is expected to begin next year at an existing power station site in Woodbridge, N.J.

The $600 million dual-fuel gas-turbine facility is set to deliver power to the PJM market for the summer of 2018.

The project was finalized after clearing the Base Residual Auction in August.

More: Black & Veatch

Line Replacement has Wisconsin Residents Worried

Residents in Onalaska, Wis., are concerned over Dairyland Power Cooperative’s planned replacement of a 65-year-old 161-kV line.

Dairyland, which is based in La Crosse, has been working nearly a decade to replace the 9-mile stretch of line connecting power plants in Alma and Genoa to the grid, and designs are not yet ready, in spite of a late 2016 start date. The cost of the project is calculated between $7 million and $8 million. Other transmission lines in the area have been rebuilt recently or are in the process of replacement.

Residents are worried that the new line, which will carry twice the electricity at the same voltage, will increase exposure to electromagnetic radiation. Dairyland says raising the wires will mitigate exposure.

More: LaCrosse Tribune

NuScale Seeking British Partners for Modular Reactor Design

NuScale Power, a U.S. company developing a small modular reactor with the help of a $217 million Department of Energy grant, is looking for a partner to help make the design a reality in the United Kingdom.

The company, mostly owned by Fluor Corp., is distributing a prospectus in the U.K. seeking a partner in what it says is a chance to get a piece of the $612 billion nuclear market by 2035.

NuScale’s design is on track to come up for U.S. certification next year, and the company says it expects to receive U.S. regulatory approval in the early 2020s. It is currently developing a test model in Idaho, using technology that can be customized for scale, allowing deployment in series, with up to 12 small reactors totaling about 600 MW.

More: Nuclear Street

Indiana’s Rising Power Prices Drive Pushback

Northern Indiana natural gas and electric provider NIPSCO has asked state regulators for an 11.5% hike in residential electric rates. Indiana’s industrial utility customers are protesting the request.

Joseph Hamrock, CEO of NiSource, parent company for NIPSCO and utilities in six other states, said the increases are needed to fund plants, poles and wires that serve as fail-safes even in light of new generating technologies.

More: NWI Times

South Field Energy to Build 1,100-MW Nat Gas Plant in Ohio

South Field Energy announced plans to build a $1.1 billion, 1,100-MW natural gas-fired power plant in Columbiana County, Ohio.

South Field and other companies are taking advantage of the cheap gas being produced at Utica Shale fields in the state. It is the sixth natural gas plant under construction in Ohio, according to the Akron Beacon Journal.

Construction would start in 2017, and the plant should be operational by 2019. South Field is also building an $899 million gas-fired plant in Carroll County.

More: Akron Beacon Journal

Ameren Increases Quarterly Dividend by 3.7%

Ameren increased its quarterly dividend on common stock, from 41 cents/share of common stock to 42.5 cents, an increase of 3.7%. The common share dividend is payable Dec. 31 to shareholders of record at the close of business on Dec. 9. The company’s board of directors also declared quarterly cash dividends to all classes of Ameren Missouri stock and all classes of Ameren Illinois preferred stock.

More: Ameren

October 13, 2015

APPA: $7.3B Capacity Performance Price Tag Unnecessary

By Rich Heidorn Jr.

A study released last week by the American Public Power Association estimates that PJM’s Capacity Performance rules will increase costs to consumers by $7.3 billion over the 2016-2019 delivery years — a tally in line with PJM’s own estimates.

But while PJM says the increased capacity costs will pay off in improved reliability and reduced energy market prices, APPA says the spending is not justified.

“PJM’s recent changes are an over-reaction to the ‘polar vortex’ and address a problem that was largely already addressed by PJM and market participants through various other measures,” said Joe Nipper, APPA’s senior vice president of regulatory affairs and communications. “As a result, bill-paying consumers will pay a lot more for the same product.”

The report was prepared by James Wilson, who also consults for state consumer advocates in PJM. Wilson said that the transition auctions recently held for the 2016/17 and 2017/18 delivery years resulted in $4 billion in additional costs to upgrade 60% and 70% of “base” capacity to Capacity Performance, respectively.

In addition Wilson estimates that the Base Residual Auction for 2018/19, which cleared at $164.77/MW-day, would have cleared at $124.23/MW-day if not for the requirement that 80% of the resources acquired be CP. That, Wilson said, increased the total BRA cost to $10.9 billion, an increase of $3.3 billion. Wilson’s quantitative findings are in line with PJM’s own calculations.

PJM said the incremental cost of the 2016/17 transition auction was $2.3 billion, slightly below the estimate of $2.5 billion to $3.6 billion PJM and the Independent Market Monitor had predicted in a joint analysis. The increase for 2017/18 was $1.7 billion, PJM said (versus an estimate of $3.1 billion to $4.2 billion).

The RTO said the 2018/19 BRA represented a $3.4 billion increase over the previous year’s auction, an amount that is within the $2 billion to $5 billion range PJM and the Monitor had expected. (See PJM Transition Auction Means Reprieve for Exelon Nukes.)

Different Conclusions

But while Wilson’s math generally agrees with PJM’s, he does not agree with the RTO over what ratepayers are getting for their money.

“Improved generator performance certainly would have resulted in much lower energy costs during the ‘polar vortex’ period of extreme cold in early 2014, when very high forced outage rates caused price spikes in the PJM energy markets,” Wilson wrote. “However, that very extreme period followed 19 winters during which such extreme cold did not occur, capacity was never scarce during winter and winter energy prices remained low in PJM.

“The polar vortex period revealed accumulated fuel and winterization issues at many plants. Apparently, many of these issues were resolved by the winter of 2015, when performance was much improved. The improved performance in winter 2015 reflects numerous steps taken by market participants and PJM following the polar vortex events, and well before Capacity Performance was approved or implemented.

“So it is unclear that CP is likely to have a substantial incremental impact on future energy prices. The expected value of the incremental impact of CP on future annual energy prices is likely an order of magnitude lower than the estimated impact on capacity cost developed in this report.”

“The combination of the changes to the [variable resource requirement] curve and the CP rule changes caused capacity prices in the 2018/2019 BRA to be higher than they otherwise would have been,” PJM said in a statement. “However, PJM is confident that the implementation of Capacity Performance has been the right approach to making the grid more reliable and benefiting consumers, and that consumers will, in fact, enjoy substantial benefits in the form of lower energy prices should extreme weather conditions materialize again as they have in the recent past. The results of the annual and transitional auctions demonstrate the market was ready and prices were competitive.”

While supply stakeholders are upset over CP’s costs, some generators are pushing to relax what they say are unduly harsh non-performance penalties. (See Generators Seek to Reopen PJM Capacity Performance Rules.)

October 8, 2015

Massachusetts Regulators Endorse Pipeline Contracts

By William Opalka

The Massachusetts Department of Public Utilities has ruled that electric distribution companies can sign contracts for natural gas capacity and pass the costs on to electric ratepayers (15-37).

Proponents of building gas infrastructure to supply electric generation have argued that the increasing reliance on natural gas requires additional pipelines to increase supply and lower high prices in the winter. After an investigation and proceeding, the DPU on Oct. 2 said the Electric Restructuring Act of 1997 did not preclude it from approving such contracts.

“The department finds that an EDC contract for pipeline capacity would be consistent with the Restructuring Act if an EDC is able to demonstrate that entering into a contract would result in cost savings for EDC ratepayers and otherwise satisfies the standard of review for approving EDC gas capacity contracts,” the order states.

The DPU’s order was in response to the state Department of Energy Resources’ April 2 petition requesting an investigation into ways new natural gas capacity could be added. The department sought to determine if there was an “innovative mechanism” for EDCs to add new natural gas capacity into the region to benefit electric ratepayers, and if cost recovery was appropriate.

“An EDC must demonstrate that the proposed contract (1) results in net benefits for the Massachusetts EDCs’ customers at a reasonable cost, and (2) compares favorably to the range of alternative options reasonably available to the EDC at the time of acquisition of the resource or contract negotiation,” the DPU order said.

Kinder Morgan subsidiary Tennessee Gas Pipeline, which is developing the proposed Northeast Energy Direct pipeline, said the order “is an important step in ensuring that electric generators have reliable access to the fuel needed to generate electricity within the ISO-NE transmission grid.” The project is among those that could be funded under the order. (See NH PUC Staff: Northeast Energy Direct Pipeline Would Lower Power Prices.)

A critic of the move, Massachusetts Attorney General Maura Healey, had argued during the proceeding that the restructuring law limited the regulators’ ability to act and questioned their assumptions. “Because of legal concerns with the DPU’s proposal and the risk to ratepayers, throughout this proceeding, our office urged the department to fully and carefully analyze the need for additional gas capacity before moving forward with any proposal that requires customers to bear the risk of a large infrastructure project,” said Chloe Gotsis, spokeswoman for the attorney general.

This is not the last word from Healey’s office. In July she commissioned a study to address the need for additional gas capacity in New England region. The study is expected by the end of the month.

The company producing the study, Boston-based The Analysis Group, has already looked askance at another Massachusetts energy proposal that it says saddles ratepayers with excessive costs. It recently conducted a study for the New England Power Generators Association critical of imported Canadian hydropower. (See New England Generators: State Interventions Risk Market Development.)

October 6, 2015

D.C. Mayor Announces Deal on Exelon-Pepco Merger

By Suzanne Herel

D.C. Mayor Muriel Bowser and Exelon CEO Chris Crane announced Tuesday that Exelon would invest $78 million in the district and protect consumers from rate hikes for three years under a settlement they hope will persuade the Public Service Commission to approve the company’s $6.8 billion acquisition of Pepco Holdings Inc.

“I believe this proposal is good for our economy and environment, and I’m asking the PSC to support the merger,” Bowser said in an afternoon press conference that also featured two former critics of the merger: People’s Counsel Sandra Mattavous-Frye and Attorney General Karl Racine.

“My sole objective has been to assure all consumers receive tangible and measureable benefits. … The applicants came back and took us seriously — they made major concessions,” Mattavous-Frye said. “The bottom line is: This is a good deal.”

Racine, who had filed a 40-point critique of the merger with the PSC and went on to be part of the negotiating team, also gave his support.

“We believe we’ve got a good deal that does look out for the ratepayers on Day 1,” Racine said. “I’m satisfied that we’ve pushed Pepco-Exelon to do the right thing.”

Bowser said the joint applicants are awaiting guidance from the PSC on what form the filing should take — a new application or an amendment to the existing case.

One of the main concerns dogging the deal has been a perceived conflict of interest between Exelon’s commitment to its nuclear fleet and pursuing the district’s goal of renewable energy.

Mattavous-Frye said the concern would be addressed with “checks and balances” included in the settlement.

“We have provisions that require the company to implement specific environmental and sustainability policies,” she said, including the strengthening of “ring-fencing” protections separating PHI’s finances from that of Exelon’s nuclear fleet and its other affiliates.

Anya Schoolman, president of solar power advocate group DC SUN, said the settlement “does nothing to change the fundamental conflict of interest identified by the Public Service Commission.”

“Allowing Exelon to take over Pepco will take money out of the pockets of D.C. ratepayers while providing them no tangible benefit,” Schoolman said. “It will also harm the ability of D.C. residents to develop their own clean, cost-effective energy. The token renewable energy provisions in the Exelon settlement are a smokescreen that will allow the company to dismantle the progress the district has made to develop renewable energy.”

The $78 million investment is five times more than Exelon’s initial pledge of $14 million and would go toward promoting sustainability, increasing reliability and supporting low-income residents, Bowser said.

Of that, $17 million would be put toward conserving natural resources and the environment and promoting energy efficiency. The merger, she said, will improve reliability, in part by allowing microgrids to connect to the grid.

Exelon also would set aside $25 million to offset rate increases through March 2019, and within 60 days of the merger it would disburse $14 million to customers — a one-time credit of about $50.

Exelon and PHI have committed to moving 100 jobs to the district from elsewhere and hiring at least 102 union employees within two years, meanwhile dedicating $5.2 million in workforce training for district residents, Bowser said.

“I believe this settlement is in the best interest of the district now and in our future,” said the mayor, saying that it reflects the “fresh approach to energy” she has brought to the district.

Said Mattavous-Frye: “My goal has been to ensure all customers, but particularly residential customers, got the best deal possible. … I could not, without abrogating my statutory responsibility, not take into account how consumers would benefit. I will do everything in my ability to make sure these commitments are followed through.”

Exelon’s Crane also spoke briefly. “We really do appreciate the responsibility of serving the nation’s capital,” Crane said, adding, “The last 30 days has been very beneficial for us.

“Our enhanced local presence will continue to drive our focus on what the needs are in the community.”

The merger already has been approved by FERC and regulators in Delaware, New Jersey, Maryland and Virginia. The state deals contain a “most favored nation” status, which means the companies may have to revisit those agreements to achieve parity with the concessions being offered the district.

“We will have to sit down and determine what effect this will have on Delaware’s settlement,” said Dallas Winslow, chair of the Delaware Public Service Commission. Winslow said he could not comment further because the issue will come before him and the commission.

Pepco shares rose Tuesday afternoon as word of the settlement circulated, with shares rising as high as $26.49 in after-hours trading, up more than $1 on the day. Exelon shares, which also rose earlier in the afternoon, fell after the details became clear, closing down 9 cents to $30.21 and falling further after hours.

Last week, Exelon asked the agency to reconsider its decision, taking issue in a 43-page filing with the PSC’s findings that the deal would not be in the public interest and it would not be in the public interest to identify additional conditions that could make it so. The filing came at the same time the mayor confirmed her office was discussing a settlement. (See Exelon Appeals DC PSC Decision; DC Mayor Confirms Negotiations.)

October 6, 2015

MISO Considering Raising Energy Offer Cap

By Tom Kleckner

LITTLE ROCK, Ark. — MISO said last week it may increase its energy market offer cap to $1,500/MWh this winter in response to expected FERC action.

Staff told the Market Subcommittee last week it is considering three interim energy offer cap options: 1) no change from current practices; 2) last winter’s revenue sufficiency guarantee (RSG) approach, which offered compensation through uplift; and 3) increasing the energy cap above the current $1,000/MWh.

Because MISO has increased its reliance on gas-fired generation, a repeat of the gas price spikes seen during the 2014 polar vortex could result in hundreds to thousands of megawatts of capacity exceeding the current cap, Markets System Analyst Chuck Hansen told the group.

MISO’s market engineering team has already tested systems for energy offers up to $3,000/MWh and found no issues that would prevent a higher cap. The team also simulated higher gas prices by increasing offer curves for gas plants and found that market signals became distorted as the price signals reached the cap, Hansen said.

Hansen said increasing the energy offer cap to $1,500/MWh would accommodate gas prices reaching $100/MMBtu, but studies show offers above that would increase the likelihood of the system marginal price being greater than the value of the lost load when operating reserves are scarce.

“Anything we do should not be considered permanent, given FERC’s pending action,” said Jeff Bladen, MISO’s executive director of market design.

FERC on Sept. 17 announced its intention to take action on offer caps and other price formation issues, though it offered no timeline. The statement came in a Notice of Proposed Rulemaking (RM15-24) that would require organized markets to settle real-time energy and operating reserve transactions financially at the same five-minute time interval that it dispatches those resources. (See NOPR Requires RTOs Switch to 5-Minute Settlements.)

MISO Market Monitor David Patton has been recommending five-minute settlements since his 2012 State of the Markets Report.

“Any time you’re selling a product,” Patton told the MSC, “I believe you should be paid for the value of the product in the time period it is being delivered.”

Some stakeholders expressed support for the 2014-15 winter solution and apprehension for raising the energy cap.

“We really want your feedback,” Bladen said, urging input on fixed-offer caps and whether generators should be able to recover verifiable fuel costs beyond the cap using uplift, as was the case last winter.

Based on the feedback (due Oct. 6), MISO will present and discuss its proposal at the Oct. 27 MSC meeting. It has targeted Nov. 1 for a FERC filing, with a Jan. 1 implementation date.

Hansen said FERC’s guidance will be incorporated into a permanent offer cap solution. He said MISO will continue to monitor neighboring RTO actions on offer caps and coordinate as appropriate.

On Thursday, two days after the MSC meeting, PJM stakeholders overwhelmingly approved increasing the RTO’s energy offer cap from $1,000/MWh to $2,000/MWh. (See related story, PJM Members OK $2,000/MWh Energy Market Offer Cap.)

October 6, 2015

EPA Ozone Rule May Mean Changes for 30+ Coal Units

By Amanda Durish Cook

The Environmental Protection Agency last week tightened its ground-level ozone limits to 70 parts per billion (ppb), a less strenuous standard than some electric generators had feared and public health advocates had sought.

The National Ambient Air Quality Standards (NAAQS) rule could impact more than three dozen coal-fired electric generators lacking scrubbers or not using them full time.

In areas expected to need to reduce nitrogen oxides (NO_x) emissions under the rule, EPA’s Regulatory Impact Analysis identified 37 coal-fired generators that either do not have selective catalytic reduction (SCR) systems (30 units, 5.4 GW) or have the scrubbers but do not always use them (seven units, 3.1 GW).

In addition, new generators could be restricted in the more than 350 counties that EPA says will not meet the 70 ppb standard.

Ozone, the main component of smog, aggravates lung diseases, including asthma, emphysema and bronchitis. It forms when emissions of NO_x, volatile organic compounds (VOCs), carbon monoxide and methane are heated by the sun. Utilities, industrial facilities, motor vehicle exhaust, gasoline vapors and chemical solvents are the major man-made sources of NO_x and VOCs.

Industry Reaction

The agency last visited the issue in 2008, when it released a 75 ppb recommendation. EPA was considering a range between 65 and 70 ppb for an eight-hour average.

The Edison Electric Institute had pushed for a new standard at the top end of the range. “While compliance challenges remain with the new standard at 70 ppb, EPA has recognized the serious implementation concerns raised by stakeholders of setting the standard below 70 ppb,” EEI President Tom Kuhn said in a statement.

The ozone standard doesn’t directly apply to power producers but to their states. David Flannery, legal counsel for the Midwest Ozone Group, said that it’s “too early to tell” how either will be affected. The group represents coal-burning utilities including American Electric Power, Duke Energy and Ameren.

“States will have to decide how they’re going to apply this ambient air standard,” Flannery said. “There’s a mix of sources that contribute. This includes cars and mobile sources in addition to the industrial sources.”

Flannery said that states are still planning how to meet 2008’s 75 ppb rule. “Part of the criticism of the new standard is that the EPA introduced the new standard before the old one could be fully implemented,” he said.

Implementation

EPA said it is tightening the standard based on more than 1,000 recent studies that suggested the current limit did not adequately protect public health.

Assuming it survives anticipated legal challenges, the next step in enforcing the ruling is to designate attainment and nonattainment areas. States will have to suggest designation areas within a year; EPA will make designations by October 2017 using air quality data from 2014 to 2016.

States identified with nonattainment areas will be forced to devise emission inventories and establish a preconstruction permitting program. The preconstruction permits apply to “new or expanding sources of air pollution,” including power plants, industrial boilers and factories.

Any state containing nonattainment areas sorted into the “moderate” or higher category will have until 2021 to design state implementation plans demonstrating the pollution-reducing steps they will take to comply. Deadlines for compliance from nonattainment areas will range from 2020 to 2037.

The agency estimated the new standard will cost $1.4 billion while producing health benefits of $2.9 billion to $5.9 billion.

It says compliance with the new threshold will be made easier by existing environmental rules, including emission control requirements for motor fuels and vehicles, the Mercury and Air Toxics Standards (MATS) and the carbon emission reductions under the Clean Power Plan.

‘Missed Opportunity’

EPA says average ozone levels have dropped 33% nationally since 1980 and that more than 90% of areas designated nonattainment for the 1997 ozone standards now meet those standards. EEI says the electric power sector has reduced sulfur dioxide (SO₂) emissions by 80% and NO_x by almost three-quarters since 1990 despite increased power demand.

Michael Brune, executive director of environmental advocate Sierra Club, called the rule “a modest step” and “a missed opportunity.”

“Over the past seven years, medical scientists have been clear that any standard above 60 ppb puts our communities at risk and is especially dangerous to children, seniors and people with respiratory illnesses,” Brune said in a statement.

October 6, 2015

FERC Sides with Developer in NYISO Dispute

By William Opalka

FERC on Wednesday sided with a Long Island power plant developer in its dispute with NYISO over interconnection standards the ISO sought to apply to the company’s proposed 750-MW combined-cycle facility (EL15-84).

The developer of Caithness Long Island II filed a complaint July 10 claiming that NYISO’s application of a local reliability requirement violates its Tariff and FERC Order 2003.

Caithness sought to prevent NYISO from applying the Long Island local reliability interface transfer capability test to identify required system upgrades as part of its interconnection facilities study.

“We find that the Long Island guideline constitutes a deliverability test and therefore using it to identify system upgrade facilities is inconsistent with Order No. 2003 and violates the [Tariff],” FERC wrote.

Order 2003 requires transmission providers to offer two levels of interconnection service: energy resource interconnection service (ERIS) and network resource interconnection service (NRIS). ERIS is a minimal interconnection service and NRIS is a more flexible service for resources that seek to be designated network resources or capacity resources.

To obtain NRIS, the interconnection customer has to satisfy a deliverability test to ensure that its generating facility can be operated simultaneously at peak load along with other generators in the same electrical area and that any output produced above the area’s peak load requirements can be transmitted to other locations on the transmission provider’s system.

The Caithness II project in Brookhaven has proposed an interconnection with the Long Island Power Authority. Caithness had requested basic ERIS service.

Caithness complained that NYISO’s Long Island guideline would allow transmission owners to act unilaterally to cause “an unjustifiable increase in interconnection costs measured in the hundreds of millions of dollars” for the project.

FERC agreed, saying the guideline is “impermissible because it creates a conflict with the NYISO minimum interconnection standard by imposing a deliverability requirement on a project requesting energy-only interconnection under ERIS.”

While NRIS studies are required to identify network upgrades needed to allow the generator to contribute to meeting the overall capacity needs of the control area or planning region, ERIS studies are not, FERC said.

October 6, 2015January 30, 2024

Company Briefs

Chesapeake Energy, the Oklahoma City-based shale drilling company, laid off about 15% of its workforce last week, saying the cuts were necessary to survive the downturn in natural gas and oil prices.

“The current commodity price environment continues to be a challenge for our industry and for Chesapeake,” Chief Executive Doug Lawler wrote to employees. “While this was extremely difficult, we are acting decisively and prudently to enhance the long-term competitiveness and strength of Chesapeake.”

Chesapeake said it laid off 740 of its 5,000 employees. Chesapeake tried to weather the wholesale price downturn by ramping up production and selling off some properties, but it wasn’t enough.

More: Wall Street Journal; Associated Press

Xcel Shuttering 2 Sherco Units by 2026

Xcel Energy announced Friday that it would retire two units at its largest coal plant by 2026 to meet carbon emissions mandates under the Environmental Protection Agency’s Clean Power Plan.

The company’s analysis concluded it could close the units at the Sherburne County Generating Station, or Sherco, in Minnesota without affecting reliability. Xcel said the retirement, along with other planned changes, will cut its carbon emissions by 60% from 2005 levels.

It said it plans a transition period of eight to 10 years before final shutdown and is examining the possibility of using the site for a gas-fired plant or solar generation.

More: Midwest Energy News

FirstEnergy Solutions Dropping PECO Customers in October

The retail electricity arm of FirstEnergy has decided it can no longer afford the good deals it offered PECO Energy customers when the Ohio-based company ventured into the territory three years ago.

FirstEnergy Solutions mailed letters to its PECO customers, saying it was declining to renew the fixed-rate deals. If those customers don’t choose a different competitive supplier, they will revert to PECO by default. The company didn’t say how many customers it was dropping, but a similar contraction in western Pennsylvania earlier this year resulted in a reduction of 36,000 Duquesne Light customers being supplied by competitive energy suppliers.

“We didn’t have all that risk built into the pricing,” said Diane Francis, a company spokeswoman. “We actually had to go out and buy power for those customers.”

More: The Philadelphia Inquirer

Kenergy, Kentucky Municipality Argue over Development’s Energy

Kenergy has filed a lawsuit against Owensboro Municipal Utilities in a dispute over which utility has the rights to supply power to the mammoth Gateway Commons mixed-use development in Kentucky.

Kenergy claims the company is entitled to provide power in the part of Gateway Commons that falls within what the company calls its “exclusive service territory,” and that OMU is attempting to “selectively encroach” on that territory. But OMU claims in court documents the city utility has a “right” to provide power to the entire development because the Gateway Commons property is inside the city limits.

Gateway Commons is planned as a $334 million “lifestyle center” that will include residential, retail and entertainment centers.

More: Messenger-Inquirer

Overhead Line Upgrade Continues in New Orleans

Entergy New Orleans said work will begin this week on the second phase of $30 million in system improvements in New Orleans.

The utility is replacing existing overhead transmission lines with 3M aluminum conductor composite reinforced wire. According to Entergy, the lines will improve reliability and deliver more transmission capacity. The company also said it can complete the upgrade without having to replace steel transmission poles currently in use.

Work on the project, which began in mid-July with phase one, is scheduled to wrap up next March. The work is part of an effort to phase out the Michoud generating facility, which has produced power since the 1960s.

More: New Orleans City Business

Nebraska Utilities Look Out-of-State to Meet Their Energy Needs

A handful of local utilities in the northeast corner of Nebraska have decided to switch from the Nebraska Public Power District to a different supplier, taking advantage of the flexibility offered by the region’s power grid. The utilities say they will save some money under better contract terms.

South Sioux City signed a contract with Lincoln Electric System for electricity starting in 2017. A group of other municipal utilities — Northeast Nebraska Public Power, Wakefield and Wayne — all plan to buy electricity from Big Rivers Electric Cooperative in Kentucky in 2018.

NPPD’s 75 wholesale customers are weighing their options this fall because the state’s largest utility wants its customers to sign new 20-year contracts that start in January, to help it plan for the future. Buying power from elsewhere is possible now after Nebraska joined SPP in 2009.

More: Associated Press

North Dakota Wind Farm Project Underway After 8 Years

Xcel Energy recently broke ground on the $300 million Courtenay Wind Farm in eastern North Dakota, after eight years of planning and development work.

Geronimo Energy began the project in 2007 and turned it over to Xcel in May. The Courtenay project will supply 200 MW of electricity at its planned completion in late 2016.

More: The Jamestown Sun

Kentucky Munis Organize for Lower-Cost Electricity

Ten municipal utilities, including Owensboro Municipal Utilities, met for the first time recently to organize an effort to acquire power at a price lower than most of them now buy from PPL’s Kentucky Utilities.

Nine of the 10 utilities in the Kentucky Municipal Power Agency are now Kentucky Utilities customers. The 10th, Owensboro, has its own generation capacity and stands to be both a supplier and customer of the agency.

The board members addressed several organizational matters Sept. 24, including the election of officers, approval of bylaws, hiring staff and a request for proposals to buy electricity on the open market beginning in 2019 from coal, natural gas and possibly renewable energy suppliers.

More: Messenger-Inquirer

PSE&G’s Kinsley Solar Farm Lauded

Public Service Electric & Gas’ Kinsley Solar Farm was chosen as the New Jersey Association of Energy Engineers’ 2014 renewable energy project of the year.

The 35-acre, 11.18-MW facility, located on the former Kinsley landfill in Deptford, N.J., is part of PSE&G’s plan to build 125 MW of grid-connected solar. With 36,841 solar panels, the Kinsley farm provides enough electricity to power about 2,000 average homes annually.

Including Kinsley, PSE&G has seven solar farms built on landfills or brownfields. An eighth is expected to go into service by the end of 2015.

More: Public Service Enterprise Group

AEP Sells Commercial Barge Subsidiary for $400 Million

American Electric Power will sell AEP River Operations to American Commercial Lines for about $550 million. The commercial barge subsidiary delivers about 45 million tons of products annually, including 10 million tons of coal.

AEP expects to net about $400 million and plans to invest the funds in its regulated business. Meanwhile, it continues to evaluate the future of its competitive generation business.

More: American Electric Power

Columbia’s East Side Expansion Project Comes Online

Columbia Pipeline on Friday announced that the East Side Expansion Project has been put into service by subsidiary Columbia Gas Transmission.

“East Side is an important piece of our project backlog, which is designed to meet the needs of both producers and end-use markets over the next several years,” Columbia Pipeline Group President Glen Kettering said.

The two new pipeline loops create additional capacity for 312 million cubic feet of gas per day. They include 9 miles of line in Chester County, Pa., and another 9 miles in Gloucester County, N.J. The project also includes two new 4,700-horsepower compressors in Pike County, Pa., and two new 10,000-horsepower units in Northampton County, Pa.

More: Columbia Pipeline Group

Calpine Closes on Champion Acquisition

Calpine has closed on its acquisition of Champion Energy Marketing, a retail electric provider based in Houston. Previous reports valued the deal at $240 million.

Champion’s majority shareholder is Houston Astros owner Jim Crane and his Crane Capital Group. EDF Trading, a subsidiary of the France-based electric utility EDF, owned 25%.

“The addition of Champion Energy is an important step in our concerted effort to create more channels for our wholesale power by getting closer to customers,” said Trey Griggs, Calpine’s executive vice president and chief commercial officer.

More: Calpine; FuelFix

WEC Selling CNG Business Acquired from Integrys Purchase

WEC Energy Group has decided that operating a chain of compressed natural gas fueling stations doesn’t fit in with its overall business plan and is selling its Trillium CNG business.

Trillium was included in WEC’s $9.1 billion acquisition of Integrys last summer. It operates 66 public stations and 43 private fueling stations. Analysts put Trillium’s value at $140 million.

“It’s not their core business and feel that it would have better attention with someone who understands that business, versus a regulated utility,” company spokeswoman Lisa Prunty said. “Trillium continues to see robust growth in a rapidly developing industry and WEC sees significant value in Trillium. It’s a highly respected brand. However it’s just inconsistent with a utility risk profile.”

More: Milwaukee Journal-Sentinel

October 6, 2015

Reports: Exelon Considering DC HQ to Win Pepco Deal

By Suzanne Herel

Chicago-based Exelon would open a headquarters in the district and offer more customer credits under a tentative agreement D.C. Mayor Muriel Bowser’s office has reportedly struck to support the company’s purchase of D.C.-based Pepco Holdings Inc.

While neither Bowser’s office nor the companies would confirm the draft settlement, several intervenors in the merger process told Bloomberg and the Washington City Paper that the document was being shared among interested parties on Friday.

The move comes as the D.C. Public Service Commission is scheduled to decide Wednesday whether to grant a joint request by the district’s attorney general and the companies to stay proceedings in the matter until Nov. 4. The request is an attempt to buy time to strike a deal that might be acceptable to the D.C. PSC, which unanimously rejected the acquisition in August. (See DC Halts Exelon’s Acquisition of Pepco Holdings; Pepco Stock Tumbles.)

Wall Street remains skeptical that Exelon will consummate the deal.

Exelon shares closed Monday at $30.30, up 1.6% for the day, while Pepco rose 0.4% to $25.41. But both remain about $2 below their prices on Aug. 24, before the PSC’s rejection.

Exelon Appeal

Last week, Exelon asked the agency to reconsider its decision, taking issue in a 43-page filing with the PSC’s findings that the deal would not be in the public interest and it would not be in the public interest to identify additional conditions that could make it so. (See Exelon Appeals DC PSC Decision; DC Mayor Confirms Negotiations.)

The filing came at the same time the mayor confirmed her office was discussing a settlement agreement with the companies that would constitute a new filing to the commission. Previously, Bowser’s office had said it agreed with a letter of opposition filed by Attorney General Karl Racine’s office listing 40 conditions that should be met for the deal to be accepted.

Negotiations Continuing

On Monday, Racine spokesman Rob Marus said it was premature to say whether the attorney general would support the outcome of negotiations, which he said were continuing.

“The settlement to be weighed in on is a different settlement,” he said. “The Office of the Attorney General has a role to weigh in early on in the process; now we’re in a different place in the process.”

Marus said Racine, whose former law firm did work for Pepco, had recused himself from the issue.

According to the City Paper, Robert Robinson, president of the Grid 2.0 Working Group, was among the intervenors who viewed the working settlement.

He said the district government won more concessions because of its initial opposition, but the agreement still represents an “about face” that doesn’t address all the issues. “We’re going to get locked into a deal of economic slavery, of continuing to pay higher and higher prices,” he said.

Unique Concessions

D.C. is the last holdout to the $6.8 billion deal, which already has been approved by FERC and regulators in New Jersey, Virginia, Maryland and Delaware. The states negotiated their agreements on a “most favored nation” status, meaning that if any subsequent agreement were more beneficial, it would have to be bestowed in kind on them.

In making its decision, the D.C. PSC said it weighed seven factors of public interest, among them the effects on ratepayers and shareholders, market competition and preservation of natural resources and the environment.

Roger Berliner, a regulatory attorney and Montgomery County councilman who led opposition to the merger in Maryland, said he suspects the settlement will be largely unique to D.C. and not invoke changes to the other states’ agreements.

For example, he said, Pepco is headquartered in D.C. If Exelon agrees to open another headquarters, it wouldn’t have to provide the same concession elsewhere.

“It’s hard for me to imagine how they would strike a deal that would trigger the most favored nations clause,” Berliner said.

He also was skeptical about Exelon being able to offer a commitment to renewable energy that would overcome the commissioners’ concerns.

“We had settlement negotiations with [Exelon] and said, ‘If you are prepared to be the best in the country when it comes to renewables, we can have this conversation,’” he said. “Clearly that was something they were not prepared to do.”

That, Berliner said, underscored the concern — also perceived by some in D.C. — that Exelon’s nuclear portfolio presents an insurmountable conflict of interest with a commitment to renewable energy.

Sides Mobilize

In D.C., the most vocal support for the deal has come from the business community and dozens of charitable groups who receive funding from Pepco.

In a media blitz that included churches, minority groups and former D.C. Mayor Anthony Williams, supporters urged reconsideration of the merger, saying it would bring increased grid reliability, jobs and opportunities for minority businesses.

“We know that reliability will be enhanced,” James Dinegar, president of the Greater Washington Board of Trade, said in a video posted on the merger partners’ website. “It’s the right move for strengthening this region and then positioning us as we continue to grow to be the strongest region in the country.”

Pepco Chairman Joseph M. Rigby is a former chairman of the Board of Trade and currently serves on its senior council.

Opposition to Stay

Opposing the acquisition are more than half of the district’s Advisory Neighborhood Commissions and nearly half of the 12-member City Council. The Office of People’s Counsel, which also has advised against approval without significant concessions, could not be reached for comment on Monday.

Meanwhile, the Grid 2.0 Working Group and D.C. Public Power filed their opposition to the request for a stay.

If the settlement constitutes a new filing, Grid 2.0 argued, it and Exelon’s request for a reconsideration should be considered independently on parallel tracks.

In its filing, D.C. Public Power also offered an alternate solution: “There are, in fact, merger arrangements that can be practically implemented that fully satisfy public interest concerns [such as] DCPP’s proposal to buy Pepco’s D.C. assets in a divestiture from Exelon/PHI. The result would be an independent, D.C.-based not-for-profit electric power utility serving the interests of the citizens of the District of Columbia.”

October 6, 2015

Baker: Hydropower Contracts Best Way to Lower Costs

By William Opalka

Massachusetts Gov. Charlie Baker said last week that long-term contracts for hydropower are the quickest and most cost-effective way for the state to reduce rising energy costs and reach greenhouse gas reduction goals.

The first-term Republican testified before the legislature’s Joint Committee on Telecommunications, Utilities and Energy in support of his bill to mandate the state’s utilities seek long-term contracts to procure hydropower.

New England power generators have complained that elected officials’ urge to “do something” about rising power costs in the region risks market development just as power plant owners are willing to invest there. (See New England Generators: State Interventions Risk Market Development.)

Baker confronted that argument in his remarks that described how ISO-NE’s main concern is reliability and plant owners need to provide returns to their investors.

“When acting in line with their obligations, none of these players are primarily concerned with costs to the consumer or environmental considerations. That is the status quo,” he said. “We are left with the critical question of who addresses energy costs and environmental concerns. The answer to that question is us.”

The 2008 Global Warming Solutions Act mandates a reduction in greenhouse gas emissions of 25% from 1990 levels by 2020. A 2010 state energy plan said Massachusetts would need at least 1,200 MW of hydropower to reach the target.

“We are in danger of being out of compliance with our own law,” Baker said.

Hydropower on that scale would likely come from Canada, but nothing precludes hydro resources in the U.S. from bidding into any solicitations from the utilities, he said. Baker said hydro can be obtained under current law, but that is unlikely in the absence of long-term contracts.

The contracts would only be pursued if state regulators determined they were cost-effective, the governor said.

Baker also said he would consider testing the market for the viability of offshore wind projects and suggested the legislature could amend his bill to include that resource. The Cape Wind project in Nantucket Sound, under development for more than a decade, was halted after it failed to complete financing after a protracted legal battle.

The governor also repeated his call for action to reduce electricity costs, which are among the highest in the nation, through regional efforts. (See Baker: New England Must Sacrifice to Lower Costs.)